Factors controlling production in hydraulically fractured low permeability oil reservoirs

Panja, Palash; Conner, Tyler; Deo, Milind

doi:10.1504/ijogct.2016.078033

Cited by 9 publications

(5 citation statements)

References 10 publications

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“…Previous studies have shown that the liquid recoveries are significantly higher when the liquid-producing wells are operated at higher BHP . An example plot of the variation of oil recovery with drawdown (difference between the initial reservoir pressure and the BHP) is shown in Figure .…”

Section: Bhp Conditions and Oil Recoveriesmentioning

confidence: 99%

“…Previous studies have shown that the liquid recoveries are significantly higher when the liquid-producing wells are operated at higher BHP. 11 An example plot of the variation of oil recovery with drawdown (difference between the initial reservoir pressure and the BHP) is shown in Figure 6. These results were obtained by performing reservoir simulations on a low-permeability reservoir with a horizontal well and single vertical fracture.…”

Section: ■ Bhp Conditions and Oil Recoveriesmentioning

confidence: 99%

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Reducing Gas Flaring in Oil Production from Shales

2016

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It is estimated that about a third of the total gas produced from the prolific Bakken Formation, amounting to about 250 million standard cubic feet (MMSCF)/day, is either vented or flared. The gas flared in the Eagle Ford formation in Texas is also of the order of 100 MMSCF/day. The main target in these plays is liquid (oil and condensate), and the associated gas is flared or vented. Any liquid production from shale will ultimately involve surface production facilities for stabilization, treatment, and transport of produced fluids. The design and operation of the surface production facilities affect the amount and quality of the liquid produced and significantly affect the amount of gas vented. In this paper, we show that using a two-stage design improves liquid quality while reducing venting rates by up to 70%. The two-stage operation will require additional infrastructure and cost upfront but will yield considerable technical and environmental benefits and move tight oil production to a more sustainable operation. The impact of operational change in surface facility and wellhead on the sub-surface flow is also investigated in this study by simulating a conventional condensate process flowsheet with Eagle Ford fluid. Major pressure drops occur in the vertical section of the well and in the wellhead choke valve, where a change in the flow regime is observed. Up to 10% liquid fallout inside the reservoir causes a loss of production and creates a condensate bank near the wellbore, hindering the gas flow.

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Section: Bhp Conditions and Oil Recoveriesmentioning

confidence: 99%

Section: ■ Bhp Conditions and Oil Recoveriesmentioning

confidence: 99%

Reducing Gas Flaring in Oil Production from Shales

2016

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“…Surrogate‐based models 21,22 such as polynomial response surface 23‐26 and artificial intelligence method such as least square support vector machine 27‐29 and artificial neuron network are gaining interest due to high computational efficiency. In surrogate models, important parameters 30 are selected based on their hierarchy to affect the production. The main disadvantage of this approach is that the models are developed based on simplified reservoir geometries.…”

Section: Introductionmentioning

confidence: 99%

“…Unconventional reservoirs such as shales, tight formation, and so forth behave differently from conventional reservoirs 30,37,38 . Long transient state prevails in ultralow permeable reservoirs where the total average pressure does not go below bubble point for a long time.…”

Section: Introductionmentioning

confidence: 99%

Moving boundary approach to forecast tight oil production

2020

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A novel semianalytical production predictive tool for tight reservoirs based on the application of material balance on a transient linear flow system is developed in this paper. This method considers two important regions during transient production of oil reservoirs: the saturated region where gas evolves and flows with oil, and the undersaturated region where only oil flows. A zonal moving boundary approach is used to evolve the two regions as the reservoir pressure gradually decreases. A semianalytical method is used to calculate pressures in the various regions and volumetric expansions. For both black oil and volatile oil scenarios, calculations from this analytical framework are able to match reservoir pressures, oil and gas rates, and cumulative gas–oil ratios determined using a reservoir simulator. The model was also applied to wells in tight reservoirs around the United States such as the Bakken (ND) and the Eagle Ford (TX) with reasonable success.

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“…In a recent study, authors showed that normalized (with initial gas oil ratio) produced GOR is dependent on the fluid PVT properties and the flowing bottom hole pressure in ultra-low permeability reservoirs (Panja and Deo, 2016a). Another recent paper from authors examined the role of various factors in the production behavior from unconventional reservoirs (Panja et al, 2016). Produced GOR values higher than the initial dissolved GOR were observed despite the fact that the average reservoir pressure was above the bubble point pressure.…”

Section: Introductionmentioning

confidence: 99%

Productions of volatile oil and gas-condensate from liquid rich shales

Panja

Pathak

Deo

2018

Adv. Geo-Energy Res.

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The growth in productions of liquid hydrocarbons from tight formations (shales) has been phenomenal in recent years. During the production of liquids (oil and condensate), large amounts of associated gas are also produced. The economic viability of a producing well depends on maintaining a reasonable proportion of liquid. The compositions and state of reservoir fluid play an important role in producing liquids from tight formations or shales in the USA such as Eagle Ford in Texas, Niobrara in Wyoming-Colorado, and Bakken in North Dakota. Small deviation in reservoir temperature around the critical point changes the state of the fluid (volatile oil or condensate) and as a result, the production of liquid is affected. Impacts of the state of the fluid (volatile oil or condensate), reservoir permeability and operating conditions on ultimate recoveries and produced gas liquid ratio are studied here. Five different reservoir fluids representing low to high liquid hydrocarbon contents are considered. Around 2% increment in condensate recovery after 10 years of production is observed from 100 nD permeability reservoir filled with the richest fluid (fluid 5) when the well is operated at 3,000 psia compared to 1,000 psia. At the same conditions, 9.3% more condensate is recovered for the leanest fluid (fluid 1). Therefore, operating the well at higher flowing bottom hole pressure (BHP) maximized the liquid recoveries of volatile oils and condensates in case of low permeability reservoirs (100 nD). However, in case of higher permeability (1,000 nD) reservoir, lower operating pressure was preferable to increase the recovery. Conclusively, bottom hole pressure has less impact on the richer fluids and higher permeability reservoir. Operating well at higher BHP (3,000 psia) also suppresses the production of gas and relatively enhances the production of liquid. Liquid to gas ratio (LGR) declines more rapidly for 100 nD permeability reservoirs compared to 1,000 nD at BHP of 1,000 psia. High fracture permeability (1,000mD and above) appeared to negatively affect liquid recoveries at higher BHP resulting in reduction of recovery by around 2%. An optimum fracture permeability may be necessary based on reservoir permeability, operating pressure and type of fluid.

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Factors controlling production in hydraulically fractured low permeability oil reservoirs

Cited by 9 publications

References 10 publications

Reducing Gas Flaring in Oil Production from Shales

Reducing Gas Flaring in Oil Production from Shales

Moving boundary approach to forecast tight oil production

Productions of volatile oil and gas-condensate from liquid rich shales

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